NATIONAL FUEL GAS COMPANY. AGA Financial Forum May 22, 2017

Transcription

1 NATIONAL FUEL GAS COMPANY AGA Financial Forum May 22, 2017

2 Safe Harbor For Forward Looking Statements This presentation may contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words anticipates, estimates, expects, forecasts, intends, plans, predicts, projects, believes, seeks, will, may, and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; impairments under the SEC s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; financial and economic conditions, including the availability of credit, and occurrences affecting the Company s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company s credit ratings and changes in interest rates and other capital market conditions; factors affecting the Company s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers ability to pay for, the Company s products and services; the creditworthiness or performance of the Company s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; or increasing costs of insurance, changes in coverage and the abilityto obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosurein our Form 10-K availableat You can also obtain this form on the SEC s websiteat For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see Risk Factors in the Company s Form 10-K for the fiscal year ended September 30, 2016 and the Forms 10-Q for the quarter ended December 31, 2016 and March 31, The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. 2

3 National Fuel Gas Company Upstream Large, high quality acreage position in Marcellus & Utica shales 785,000 Net acres in Appalachia Midstream Expanding and modernizing pipeline infrastructure to serve growing Appalachian supply $285 million 1 Annual Adjusted EBITDA Downstream Stable, regulated earnings & cash flows 740,000 Utility customer accounts (1) For the trailing twelve months ended March 31,

4 Balanced Earnings and Cash Flows Adjusted EBITDA by Segment ($ millions) $1,500 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment $1,000 Energy Marketing & Other $852 $953 $843 $789 $815 $500 $492 $539 $422 $364 $390 $64 $69 $79 $93 $161 $186 $188 $199 $192 $0 $172 $165 $164 $149 $ TTM Fiscal Year 3/31/17 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. 4

5 Flexibility to Responsibly Deploy Capital Capital Expenditures by Segment ($ millions) $1,500 $1,000 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other (1) $970 $1,001 CapEx Reconciliation for JDA Proceeds ($millions) E&P Total NFG Gross CapEx $256 $523 JDA Proceeds ($157) ($157) Net CapEx $99 $366 $500 $0 $717 $603 $557 $450 - $530 $533 $366 $118 $210 - $250 $138 $99 $230 $54 $50 - $60 $55 $140 $114 $100 - $120 $56 $72 $89 $94 $98 $90 - $ Fiscal Year Guidance (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. 5

6 Downstream Utility Energy Marketing 6

7 Downstream New York & Pennsylvania Service Territories New York Total Customers (1) : 528,312 ROE: 8.7% (NY PSC Rate Case Order, Apr. 2017) Rate Mechanisms: o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant Function Charge (Uncollectibles Adj.) o 90/10 Sharing (Large Customers) Pennsylvania Total Customers (1) : 213,924 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge (1) As of September 30,

8 Downstream New York Rate Case Outcome On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution s rate case (No. 16-G-0257) filed in April Rate Order Summary: Revenue Requirement: $5.9 million Rate Base: $704 million (prior case $632 million 1 ) Allowed Return on Equity: 8.7% (prior case allowed 9.1% 1 ) Capital Structure: New rates effective 5/1/17 No stay-out clause 42.9% equity (1) Case 13-G-0136 rate year ended September 30,

9 Downstream Shifting Trends in Customer Usage Usage Per Account (1) 150 Residential (Mcf) 60 Industrial (MMcf) (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). 12-Months Ended March 31 9

10 Downstream Investing in Safe and Reliable Systems NY Utility Net Plant Increased $127.5 million since 2007 $125 Capital Expenditures for Safety Capital Expenditures (Millions) $100 $75 $50 $25 Total Capital Expenditures $58 $58 $56 $58 $58 $58 $72 $89 $94 $98 $90 - $100 $ E Fiscal Year 10

11 Downstream Accelerating Pipeline Replacement & Modernization Utility Mains by Material Miles of Utility Main Pipeline Replaced NY 9,700 miles Coated Bare Plastic Wrought Iron Cast Iron PA* 4,830 miles Coated Bare Plastic Wrought Iron * No Cast Iron Mains in Pa.*

12 Downstream A Proven History of Controlling Costs Utility Operation & Maintenance Expense ($ millions) $250 All Other O&M Expenses O&M Pension Expense O&M Uncollectible Expense $200 $150 $178 $193 $20 $33 $200 $28 $189 $23 $199 $24 $100 $50 $152 $151 $163 $160 $166 $ TTM 3/31/17 Fiscal Year 12

13 Midstream Businesses Gathering Pipeline & Storage 13

14 Midstream Midstream Businesses NFG Supply Corp. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage $1.3 Billion Midstream investments since 2010 Pipeline & Storage Segment Gathering Segment $191 $30 $250 $257 $64 $ Bcf/d Contracted firm transportation capacity added since 2010 Midstream Businesses Adjusted EBITDA ($MM) $278 $285 $79 $93 $161 $186 $188 $199 $192 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation TTM 3/31/17 Fiscal Year 14

15 Midstream Infrastructure Expansions Bolster Supply Diversity Expanding Our Pipelines to Assure Supply Security for New York Markets Integration of Seneca s WDA Production Into Broader Interstate System Northern Access 2015 (In-Service (1) ) System: NFG Supply Corp. Capacity: 140,000 Dth per day Delivery Interconnect: Niagara (TransCanada) Total Cost: $67.1 million Annual Revenues: $13.3 million Northern Access 2016 (Delayed) To Dawn Niagara Chippewa East Aurora In-Service: TBD Systems: NFG Supply Corp. & Empire Pipeline Capacity: 490,000 Dth per day Total Expected Cost: ~$500 million Project Status: Delayed pending appeal of NYS DEC WQC notice of denial 401 (1) 40,000 Dth per day went in-service on November 1, The remaining 100,000 Dth per day was placed in-service on December 1,

16 Midstream Northern Access Project Status National Fuel Remains Committed to Building the Northern Access Pipeline Project Project in-service not expected before 2019 due to regulatory delays February 3, 2017 NFG received FERC 7(c) certificate March 3, 2017 NFG filed petition for rehearing with FERC seeking waiver of NYS DEC Clean Water Act Section 401 WQC April 7, 2017 NY DEC issued notice of denial of WQC April 21, 2017 Filed appeal with US Court of Appeals for the 2 nd Circuit Project Spending Update: Total project spending to-date: ~$68 million Fiscal 2017 Pipeline & Storage capital expenditure guidance reduced by $115 million Minimal remaining commitments 16

17 Midstream Empire System Expansion Foundation Shipper Agreement Provides Major Commitment Needed for the Empire North Project Target In-Service: as early as Nov. 1, 2019 Estimated Cost: $150 to $200 million (scalable) Available Capacity / Delivery Points: o 180,000 Dth/d to Chippawa (TCPL) o 120,000 Dth/d to Hopewell (TGP) Major Facilities: o 70,000 hp at 3 new compressor stations in NY & Pa. o No new pipeline construction in NY 17

18 Midstream Continued Expansion of the NFG Supply System Future NFG Supply System Expansions Line D Expansion Project Line N Expansion Opportunities Target In-Service: Nov. 1, 2017 Contracted Capacity: 77,500 Dth/d from an interconnect with TGP 300 at Lamont, Pa. into Erie, Pa. market Estimated Cost: $28 million ($8 million modernization) Status: In-construction Line D Expansion Project Line N Expansion Opportunities Opportunity #1 (Supply OS #220) Project: Transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC. Open Season Capacity: 100,000 Dth/d from Hollbrook interconnect (TETCO) 73,000 Dth/d on a new 4-mile pipeline extension to facility Status: Foundation Shipper Agreement signed Opportunity #2 (Supply OS #221) Open season for 215,000 Dth/d of new south to north capacity concluded on 5/11/

19 Upstream Overview Exploration & Production 19

20 Upstream Significant Appalachian Acreage Position Western Development Area (WDA) Daily gross production: ~280 MMcf/d Fee held mineral rights with no royalty Large inventory of high quality Marcellus economic under $2/Mcf Contiguous position drives cost and operational efficiencies Fee Acreage Lease Acreage WDA - 715,000 Acres EDA - 70,000 Acres Eastern Development Area (EDA) Daily gross production: ~300 MMcf/d Primarily leased (16-18% royalty) No significant near-term lease expirations > 100 remaining Marcellus and Utica locations economic under $1.80/Mcf 20

21 Upstream Marcellus Shale: Western Development Area WDA Tier 1 Acreage 200,000 Acres WDA Highlights Clermont/ Rich Valley Large drilling inventory of quality Marcellus dry gas Fee acreage provides flexibility / enhances economics Highly contiguous position drives best in class Marcellus well costs Ridgway Hemlock NFG midstream infrastructure supporting growth Early Utica test results on trend with other Utica wells in NE Pa. WDA Tier 1 Marcellus Economics (1) EUR Color Key BCF/well 4-6 BCF/well 2-4 BCF/well Avg Avg $ % IRR Locations Lateral EUR NYMEX/Dawn Realized Remaining Length (ft) (Bcf) IRR% Price CRV 22 8, % $1.70 Hemlock/Ridgway 631 8, % $1.76 Other Tier , % $1.84 (1) Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. 21

22 Upstream WDA Utica Appraisal Initial Utica Test Wells in WDA CRV area Exceeds Marcellus Performance Normalized Cumulative (MMcf/1000') Results: WDA Utica Results vs Avg WDA Marcellus Days on Production WDA Marcellus, HU 196HU WDA-CRV Utica Test Wells WDA-CRV Marcellus Wells Well 113HU Well 196HU 113 wells (avg) Initial Test June 2016 Nov 2016 Est. EUR /1,000 ft 2.0 Bcf 1.8 Bcf 1.1 Bcf Early economic indicators: 60-80% higher EUR / foot 25-35% increase in Upstream capital per well Expect Utica well costs to range from $5 to $6 million per well Significant efficiencies from re-use of existing Upstream and Gathering infrastructure Can utilize existing and future firm transport capacity 22

23 Upstream Marcellus Shale: Eastern Development Area EDA Highlights EDA Acreage 70,000 Acres 1 DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d 1 Utica resource potential ~1 Tcf Development expected to begin in fiscal Covington & DCNR Tract 595 (Tioga Co., Pa.) 3 Gross daily production: ~100 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Added 1 Rig May 2017 FY17/18 Lycoming Dev FY18+ Utica Tioga Dev 3 Gross daily production: ~200 MMcf/d 54 remaining Marcellus locations economic < $1.60 /Mcf Atlantic Sunrise capacity (190 MDth/d) in mid-2018 Geneseo to provide additional locations Geneseo test well 24hr IP: 14.1 MMcf/d on 4,920 lateral 23

24 Upstream EDA Utica Update Seneca DCNR 007 Utica Well Among the Best in Northeastern PA Northeast PA Utica Well Performance Tioga and Potter County SRC EDA Tract 007 Utica Test Well Gathering Line In-Service November 2016 Est. EUR /1,000 ft 2.4 Bcf Normalized Cumulative (MMcf/1000') Days On Production Industry Tioga/Potter Wells Seneca DCNR H Utica DCNR 007 development expected in Tcf recoverable resource Expect well costs to range from $5.5 to $6.5 mm Midstream / Takeaway: NFG Midstream Wellsboro Gathering System Interconnect with Tennessee Gas Pipeline 300 Evaluating long-term takeaway options Source: PA DEP. Includes production from 19 Potter and Tioga County wells 24

25 Upstream Best in Class Marcellus Well Costs Marcellus Drilling Cost per Foot Marcellus Completion Cost per Stage ($000s) $300 $200 $100 $275 $208 $174 $153 $120 $110 $300 $200 $100 $248 $148 $109 $91 $67 $58 $ E $ E Seneca Average Marcellus Well Cost (1) vs. Appalachian Peers (2) $ /lateral foot $1,000 $900 $800 $700 $600 $500 $663 Seneca CRV $856 Peer 1 Peer 2 Peer 3 Peer Average Peer 4 Peer 5 Peer 6 (1) Seneca CRV reflects a $5.3 million all-in total well cost for a 8,000 ft. lateral. Total well costs include drilling, completions, allocated pad level and production equipment. (2) Appalachian peers include AR, COG, EQT, RICE, RRC, & SWN. Data obtained or recalculated from most recent peer company presentations. 25

26 Upstream California Oil Stable Oil Production Minimal Capital Investment Free Cash Flow Positive 1 East Coalinga Average Net Daily Production (BOE/D) 9,078 9,699 9,674 9,315 ~9,200 2 Lost Hills F 3 Midway Sunset Annual Capital Expenditures ($MM) $105 $83 $57 $38 $35 - $45 4 Sespe F Fiscal Year 26

27 Upstream Seneca Production 250 Appalachia West Coast (California) Seneca Net Production (Bcfe) Near-term Growth Strategy 2 rig development program Atlantic Sunrise capacity starting mid-2018 New EDA Utica development with production starting in FY19 Layer-in firm sales to take advantage of attractive regional pricing Gross production growth will benefit NFG s Gathering segment ~ Guidance Projected

28 Upstream Long-term Contracts Supporting Appalachian Production Seneca will continue to layer-in firm sales contracts with attractive realizations at regional pricing points to lock-in drilling economics and minimize spot exposure as it waits for Northern Access Gross Physical Firm Contract Volumes (Mdth/d) FYTD 2017 Avg. Spot Production In-Basin Firm Sales Contracts (1) FY FY FY FY Fiscal Year Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification 50,000 Dth/d (1) Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Regional Firm Sales Converting 95 Mdth/d of Northern Access sales from Dawn back to basin Recent deals providing attractive realizations Further regional basis improvement expected as pipeline projects are placed in-service Firm Transportation Long-term firm sales contracts in place at physical delivery points realizing NYMEX / Dawn less transport cost 28

29 Consolidated Overview 29

30 Near-term Capital Budget and Operating Plan Capital Expenditures by Segment ($MM) Strategic Plan $1,000 $750 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other $535 - $645 (1) Upstream Near-term in-basin pricing supports plans for 10%+ annual production growth over next 3 years Added 2 nd rig in May 2017 Prepare for Atlantic Sunrise capacity starting mid-2018 Begin Utica development in EDA in 2018 $500 $180 - $220 $450 - $530 Midstream $250 $65 - $75 $200 - $250 $210 - $250 $50 - $60 $100 - $120 Gathering system throughput and revenues will benefit from Seneca s production growth Continued investment in system expansion and modernization $0 $90 - $100 $90 - $100 FY 2017 Forecast (w/ Northern Access) FY 2017 Forecast (current) Downstream Continued investment in pipeline replacement and modernization (1) Reflects the netting of anticipated proceeds received from the joint development partner for working interest in joint development wells. Current E&P guidance increased $30 million to reflect changes in the timing of Seneca s development activities. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. 30

31 Strong Balance Sheet & Liquidity Debt/Adjusted EBITDA Capitalization 2.66 x 2.57 x 1.89 x 1.77 x 2.27 x Total Equity 44% Total Debt 56% TTM Fiscal Year End 03/31/17 Debt Maturity Profile ($MM) $3.7 Billion Total Capitalization as of March 31, 2017 Liquidity $600 $500 $549 $500 Committed Credit Facilities $ 1,250 MM $400 $200 $300 $250 Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 03/31/17 $ 0 MM $ 1,250 MM $ 231 MM $0 Total Liquidity at 03/31/17 $ 1,481 MM Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. 31

32 Committed to the Dividend Annual Dividend Rate ($ /share) NFG s Dividend Consistency $2.00 $1.50 $1.00 $0.50 $0.00 Consecutive Payments Consecutive Increases Current Dividend Rate 114 Years 46 Years $1.62 per Share Current Dividend Yield (1) 3.0% (1) As of May 3, Annual Rate at Fiscal Year End 32